Power and Commercial Operations:— Generated approximately 29
million MWh4 of electricity in third quarter of 2014—
Achieved low year-to-date fleetwide forced outage factor: 2.1%—
Successfully originated several new contracts, including those related
to our Geysers assets, Delta, Pastoria and Osprey power plants and our
Texas power plant fleet

Portfolio Management:— Announced acquisition of Fore River
Energy Center, a nameplate 809 MW combined-cycle and dual-fuel capable
power plant in Massachusetts, for approximately $530 million, or
$655/kW

Capital Allocation Progress:— Deployed approximately $3.1
billion of capital year-to-date toward share repurchase, balance sheet
management, organic growth and acquisitions— Completed
approximately $308 million of share repurchases since last earnings
announcement, bringing total 2014 repurchases to approximately $949
million— Issued notice to call approximately $120 million of our
7.875% First Lien Notes due 2023 at a price of 103 during the fourth
quarter

Calpine Corporation (NYSE: CPN) today reported third quarter 2014
Adjusted EBITDA of $745 million, compared to $802 million in the prior
year period, and Adjusted Free Cash Flow of $506 million, or $1.26 per
diluted share, compared to $556 million, or $1.27 per diluted share, in
the prior year period. The decreases in Adjusted EBITDA and Adjusted
Free Cash Flow were primarily due to lower Commodity Margin driven
largely by the sale of six power plants in July 2014. Net Income1
for the third quarter of 2014 was $614 million, or $1.52 per diluted
share, compared to $306 million, or $0.70 per diluted share, in the
prior year period. The increase in Net Income1 was primarily
due to a gain on the previously referenced asset sale, partially offset
by higher debt extinguishment costs and impairment losses. Net Income,
As Adjusted2, for the third quarter of 2014 was $306 million
compared to $268 million in the prior year period. The increase in Net
Income, As Adjusted2,was primarily due to a
decrease in income tax expense associated with intraperiod tax
allocations, which more than offset the previously discussed decrease in
Adjusted EBITDA.

Year-to-date 2014 Adjusted EBITDA was $1,604 million, compared to $1,431
million in the prior year period, and Adjusted Free Cash Flow was $735
million, or $1.77 per diluted share, compared to $551 million, or $1.23
per diluted share, in the prior year period. Net Income1 for
the first nine months of 2014 was $736 million, or $1.77 per diluted
share, compared to $111 million, or $0.25 per diluted share, in the
prior year period. The increase in Net Income1 was primarily
due to higher Commodity Margin, as well as those factors that drove
comparative performance for the third quarter, as described above. Net
Income, As Adjusted2, for the first nine months of 2014 was
$359 million compared to $165 million in the prior year period. The
increases in Adjusted EBITDA, Adjusted Free Cash Flow and Net Income, As
Adjusted2, compared to the prior year period were primarily
due to higher Commodity Margin resulting from stronger market
conditions, net portfolio changes and higher regulatory capacity revenue.

“Calpine delivered another strong quarter both operationally and
commercially, especially considering the mild summer weather in much of
the country,” said Thad Hill, Calpine’s President and Chief Executive
Officer. “We benefited from timely hedging, new capacity and operational
excellence throughout our fleet. Meanwhile, we also further positioned
Calpine for the future, announcing the pending acquisition of Fore River
Energy Center in New England, originating several new contracts in
California and Texas, and advancing construction of Garrison Energy
Center in Delaware and development of York 2 Energy Center in
Pennsylvania.

“Our clean, modern, efficient and flexible fleet is poised to benefit
from the secular trends playing out in the U.S. power generation
industry. In the East, our reliable operations and dual-fuel
capabilities position us to take advantage of tighter markets given the
significant upcoming capacity retirements and provide us the confidence
to be a meaningful participant in capacity markets that will command a
premium for performance. Our Texas fleet is poised to benefit from
strong demand growth, pending environmental regulations and increasing
volatility from the addition of intermittent wind. Finally, we continue
to position our California fleet for long-term stability through
contracts to support the integration of intermittent resources.

“Calpine remains firmly committed to enhancing shareholder value through
disciplined and accretive capital allocation. We are on track in 2014 to
redeploy more than $3 billion of capital into attractive growth
opportunities, debt repayment and share repurchases. Among these, we
balance share repurchases with our ability to respond to other
opportunities in the marketplace. Our foremost objective is to maximize
levered cash-on-cash returns to equity, as measured by Adjusted Free
Cash Flow Per Share, while being prudent with the balance sheet. We are
pleased to provide 2015 guidance today, that, at the midpoint of the
ranges, represents an increase in Adjusted Free Cash Flow Per Share of
approximately 19% over 2014.”

__________

1 Reported as Net Income attributable to Calpine on our
Consolidated Condensed Statements of Operations.

2 Refer to Table 1 for further detail of Net Income, As Adjusted.

3 Assuming midpoints of 2014 and 2015 guidance ranges.

4 Includes generation from power plants owned but not operated by
Calpine and our share of generation from unconsolidated power plants.

SUMMARY OF FINANCIAL PERFORMANCE

Third Quarter Results

Adjusted EBITDA for the third quarter of 2014 was $745 million compared
to $802 million in the prior year period. The year-over-year decrease in
Adjusted EBITDA was primarily related to a $41 million decrease in
Commodity Margin, which was largely due to:

–

the sale of six power plants with a total capacity of 3,498 MW in
our East segment on July 3, 2014

–

lower regulatory capacity revenue in PJM and

–

the expiration of a tolling contract associated with our Delta
Energy Center in December 2013 and a previously existing PPA
associated with our Osprey Energy Center in May 2014, partially
offset by

+

our Russell City and Los Esteros power plants commencing commercial
operations during the third quarter of 2013, the acquisition of
Guadalupe Energy Center in February 2014 and the completion of the
expansions of our Deer Park and Channel Energy Centers in June 2014
and

+

stronger market conditions resulting in higher market spark spreads
in the West and East segments.

Net Income1 was $614 million for the third quarter of 2014,
compared to $306 million in the prior year period. The year-over-year
improvement in Net Income1 was primarily due to a gain on the
previously referenced asset sale, partially offset by higher debt
extinguishment costs and impairment losses related to our Osprey Energy
Center. As detailed in Table 1, Net Income, As Adjusted2, was
$306 million in the third quarter of 2014 compared to $268 million in
the prior year period. The year-over-year improvement was driven largely
by:

+

lower income tax expense due to differences in intraperiod tax
allocations, partially offset by

–

lower Commodity Margin, as previously discussed and

–

higher plant operating expense driven primarily by an increase in
equipment failure costs related to outages and other expenses.

Adjusted Free Cash Flow was $506 million in the third quarter of 2014
compared to $556 million in the prior year period. Adjusted Free Cash
Flow decreased during the period primarily due to the decrease in
Adjusted EBITDA, as previously discussed.

Year-to-Date Results

Adjusted EBITDA for the nine months ended September 30, 2014, was $1,604
million compared to $1,431 million in the prior year period. The
year-over-year increase in Adjusted EBITDA was primarily due to a $242
million increase in Commodity Margin which was primarily related to:

+

our Russell City and Los Esteros power plants commencing commercial
operations during the third quarter of 2013, the acquisition of
Guadalupe Energy Center in February 2014 and the completion of the
expansions of our Deer Park and Channel Energy Centers in June 2014

+

higher contribution from our dual-fueled power plants in the East
during the first quarter of 2014 when fuel oil prices were lower
than natural gas prices

+

higher regulatory capacity revenue in PJM during the first half of
the year and

the sale of six power plants with a total capacity of 3,498 MW in
our East segment on July 3, 2014

–

lower contribution from hedges and

–

the expiration of a tolling contract associated with our Delta
Energy Center in December 2013 and a previously existing PPA
associated with our Osprey Energy Center in May 2014.

Net Income1 was $736 million for the nine months ended
September 30, 2014, compared to $111 million in the prior year period.
In addition to the previously mentioned factors that drove similar
improvements in Net Income1 for the third quarter, Net Income1
for the nine months ended September 30, 2014, also increased as a result
of higher Commodity Margin, as previously discussed. As detailed in
Table 1, Net Income, As Adjusted2, was $359 million in the
nine months ended September 30, 2014, compared to $165 million in the
prior year period. The year-over-year improvement was driven largely by:

higher plant operating expense driven primarily by portfolio
changes, higher equipment failure expense related to outages and the
reversal in 2013 of previously recognized regulatory fees that did
not recur in 2014.

Adjusted Free Cash Flow was $735 million for the nine months ended
September 30, 2014, compared to $551 million in the prior year period.
The increase in Adjusted Free Cash Flow during the period was primarily
due to an increase in Adjusted EBITDA, as previously discussed.

(2) In addition to changes in market value on derivatives not
designated as hedges, changes in mark-to-market (gain) loss also
includes de-designation of interest rate swap cash flow hedges and
related reclassification from AOCI into earnings, hedge ineffectiveness
and adjustments to reflect changes in credit default risk exposure.

(3) See “Regulation G Reconciliations” for further discussion of
Net Income, As Adjusted.

REGIONAL SEGMENT REVIEW OF RESULTS

Table 2: Commodity Margin by Segment (in millions)

Three Months Ended September 30,

Nine Months Ended September 30,

2014

2013

Variance

2014

2013

Variance

West

$

361

$

337

$

24

$

791

$

737

$

54

Texas

346

328

18

644

537

107

East

237

320

(83

)

786

705

81

Total

$

944

$

985

$

(41

)

$

2,221

$

1,979

$

242

West Region

Third Quarter: Commodity Margin in our West segment increased by
$24 million in the third quarter of 2014 compared to the prior year
period. Primary drivers were:

+

the commencement of commercial operations at our contracted Russell
City and Los Esteros power plants in August 2013 and

the expiration of a tolling contract associated with our Delta
Energy Center in December 2013 and

–

lower contribution from hedges.

Year-to-Date: Commodity Margin in our West segment increased by
$54 million for the nine months ended September 30, 2014, compared to
the prior year period. The year-to-date results were largely impacted by
the same factors that drove comparative performance for the third
quarter, as previously discussed.

Texas Region

Third Quarter: Commodity Margin in our Texas segment increased by
$18 million in the third quarter of 2014 compared to the prior year
period. Primary drivers were:

+

the acquisition of Guadalupe Energy Center in February 2014 and the
expansions of our Deer Park and Channel Energy Centers, which were
completed in June 2014, partially offset by

–

lower spark spreads resulting from weaker market conditions.

Year-to-Date: Commodity Margin in our Texas segment increased by
$107 million for the nine months ended September 30, 2014, compared to
the prior year period. Primary drivers were:

+

the acquisition of Guadalupe Energy Center in February 2014 and the
expansions of our Deer Park and Channel Energy Centers, which were
completed in June 2014

+

higher spark spreads resulting from stronger market conditions in
the first quarter of 2014 and

+

higher contribution from hedges.

East Region

Third Quarter: Commodity Margin in our East segment decreased by
$18 million in the third quarter of 2014 compared to the prior year
period, after excluding a decrease of $65 million resulting from the
sale of six power plants with a total capacity of 3,498 MW on July 3,
2014. Primary drivers were:

–

lower regulatory capacity revenues in PJM and

–

the expiration of a previously existing PPA associated with our
Osprey Energy Center in May 2014, partially offset by

Year-to-Date: Commodity Margin in our East segment increased by
$122 million for the nine months ended September 30, 2014, compared to
the prior year period, after excluding a decrease of $41 million
resulting from the previously discussed sale of six power plants.
Primary drivers were:

+

higher margins resulting from stronger market conditions due to
colder than normal weather during the first quarter of 2014

+

higher contribution from our dual-fueled plants during the first
quarter of 2014 when fuel oil prices were lower than natural gas
prices and

+

higher regulatory capacity revenue in PJM during first half of the
year, partially offset by

–

lower contribution from hedges and

–

the expiration of a previously existing PPA associated with our
Osprey Energy Center in May 2014.

LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES

Table 3: Liquidity

September 30,

December 31,

2014

2013

(in millions)

Cash and cash equivalents, corporate(1)

$

1,300

$

649

Cash and cash equivalents, non-corporate

229

292

Total cash and cash equivalents

1,529

941

Restricted cash

286

272

Corporate Revolving Facility availability(2)

1,294

758

CDHI letter of credit availability

101

7

Total current liquidity availability

$

3,210

$

1,978

__________

(1) Includes $67 million and $5 million of margin deposits posted
with us by our counterparties at September 30, 2014, and December 31,
2013, respectively.

(2) On July 30, 2014, we amended our Corporate Revolving Facility
to increase the capacity by an additional $500 million to $1.5 billion.

Liquidity grew to approximately $3.2 billion as of September 30, 2014.
Cash and cash equivalents increased during the nine months ended
September 30, 2014, primarily due to the receipt of proceeds from the
sale of six power plants in our East segment in July 2014. Availability
under our Corporate Revolving Facility increased primarily as a result
of an amendment that raised its capacity by $500 million during the
third quarter of 2014.

Table 4: Cash Flow Activities

Nine Months Ended September 30,

2014

2013

(in millions)

Beginning cash and cash equivalents

$

941

$

1,284

Net cash provided by (used in):

Operating activities

504

415

Investing activities

550

(468

)

Financing activities

(466

)

(207

)

Net increase (decrease) in cash and cash equivalents

588

(260

)

Ending cash and cash equivalents

$

1,529

$

1,024

Cash flows provided by operating activities in the nine months ended
September 30, 2014, were $504 million compared to $415 million in the
prior year period. The increase in cash provided by operating activities
was primarily due to an increase in income from operations (adjusted for
non-cash items). Also contributing to the increase was a decrease in
working capital employed, largely due to lower net margin requirements
partially offset by an increase in net accounts receivable/payable
balances resulting from higher Commodity Margin. Partially offsetting
these increases, debt extinguishment payments increased due to the
refinancing of our First Lien Notes during the first nine months of 2014.

Cash flows provided by investing activities during the nine months ended
September 30, 2014, were $550 million compared to cash flows used in
investing activities of $468 million in the prior year period. The
increase was primarily due to $1.57 billion of proceeds received in 2014
from the sale of six power plants in our East segment, partially offset
by $656 million used to purchase our Guadalupe Energy Center.

Cash flows used in financing activities were $466 million and were
primarily related to payments associated with execution of our share
repurchase program, partially offset by the issuance of CCFC Term Loans
used to fund a portion of the purchase price of our Guadalupe Energy
Center.

CAPITALALLOCATION

Share Repurchase Program

During 2014, we repurchased a total of 42,754,300 shares of our common
stock for approximately $949 million at an average price of $22.19 per
share. Included in the total 2014 activity is the repurchase of
13,213,372 shares of our common stock from a shareholder for
approximately $311 million in a private transaction completed in July
2014 that was approved by our Board of Directors.

Fore River Energy Center

On August 22, 2014, we entered into an agreement to purchase Fore River
Energy Center, a power plant with a nameplate capacity of 809 MW, for
approximately $530 million, excluding working capital adjustments. The
addition of this modern, efficient, natural gas-fired, combined-cycle
power plant located in North Weymouth, Massachusetts, will increase
capacity in our East segment, specifically the constrained New England
market. The plant features two combustion turbines, two heat recovery
steam generators and one steam turbine. We expect the transaction to
close in the fourth quarter of 2014 and expect to fund the acquisition
with cash on hand or financing.

Osprey Energy Center

In August 2014, we executed a term sheet with Duke Energy Florida, Inc.
related to our Osprey Energy Center for a new PPA with a term of up to
27 months, after which Duke Energy Florida, Inc. would purchase our
Osprey Energy Center. Although a definitive asset sale agreement is
still being negotiated, and any such agreement would be subject to
regulatory approval, the potential sale of our Osprey Energy Center
represents a strategic disposition of a power plant in a wholesale power
market dominated by regulated utilities.

Sale of Six Southeast Power Plants

On July 3, 2014, we completed the sale of six of our power plants in the
East segment for a purchase price of approximately $1.57 billion in
cash, excluding working capital and other adjustments. The divestiture
of these power plants has better aligned our asset base with our
strategic focus on competitive wholesale markets.

Refinancing of First Lien Notes with Senior Unsecured Notes

On July 22, 2014, we refinanced $2.8 billion of senior secured notes
with an equivalent amount of senior unsecured notes. We issued $1.25
billion in aggregate principal amount of 5.375% senior unsecured notes
due 2023 and $1.55 billion in aggregate principal amount of 5.75% senior
unsecured notes due 2025 in a public offering, representing the
inaugural issuance of unsecured debt within our capital structure. We
used the net proceeds, together with cash on hand, to repurchase our
2019 First Lien Notes, 2020 First Lien Notes and 2021 First Lien Notes,
which carried interest rates of 7.50% - 8.00%. In connection with this
refinancing, we incurred approximately $350 million in early retirement
premiums and fees, and we expect to achieve annual interest savings of
approximately $60 million.

2023 First Lien Notes

In November 2014, we issued notice to the holders of our 2023 First Lien
Notes of our intent to redeem 10% of the original aggregate principal
amount, plus accrued and unpaid interest. We intend to use cash on hand
to fund the redemption.

PLANT DEVELOPMENT

Texas:

Channel and Deer Park Expansions: In June of 2014, we completed
construction to expand the baseload capacity of our Deer Park and
Channel Energy Centers by approximately 260 MW5 each. Each
power plant featured an oversized steam turbine that, along with
existing plant infrastructure, allowed us to add capacity and improve
the power plant’s overall efficiency at a meaningful discount to the
market cost of building new capacity.

Guadalupe Energy Center: On February 26, 2014, we completed the
purchase of a 1,050 MW nameplate capacity power plant for approximately
$625 million, excluding working capital adjustments. We funded the
acquisition with $425 million of incremental CCFC Term Loans and cash on
hand. The addition of this modern, natural gas-fired, combined-cycle
power plant increased capacity in our Texas segment, which is one of our
core markets. We also paid $15 million to acquire the rights to an
advanced development opportunity for an approximately 400 MW
quick-start, natural gas-fired peaker. Development efforts are ongoing
and we are continuing to advance entitlements (such as permits, zoning
and transmission).

East:

Garrison Energy Center: Garrison Energy Center is a 309 MW
combined-cycle project located in Delaware on a site secured by a
long-term lease with the City of Dover. Once complete, the power plant
will feature one combustion turbine, one heat recovery steam generator
and one steam turbine. Construction commenced in April 2013, and we
expect commercial operations to commence during the second quarter of
2015. The project’s capacity has cleared each of PJM’s three most recent
base residual auctions. We are in the early stages of development of a
second phase (309 MW) of this project. PJM has completed the feasibility
and system impact studies for this phase, and the facilities study is
currently underway.

Mankato Power Plant Expansion: We are proposing a 345 MW
expansion of the Mankato Power Plant in response to a competitive
resource acquisition process established by the Minnesota Public
Utilities Commission (“MPUC”) to acquire up to approximately 500 MW of
new capacity. The initial stage of the proceeding was managed via a
contested case hearing. On March 27, 2014, the MPUC directed Xcel Energy
(Northern States Power) to negotiate PPAs with Calpine and certain other
entities. Xcel Energy filed the negotiated PPAs on September 23, 2014,
but recommended that the MPUC delay approval. The MPUC is expected to
decide whether to approve one or more PPAs or to delay the pending
resource acquisition process during deliberations later this year.

York 2 Energy Center: York 2 Energy Center is a 760 MW
dual-fueled combined-cycle project that will be co-located with our York
Energy Center in Peach Bottom Township, Pennsylvania. Once complete, the
power plant will feature two combustion turbines, two heat recovery
steam generators and one steam turbine. PJM has completed the project’s
feasibility and system impact studies, and the facilities study is
underway. The project’s capacity cleared PJM’s 2017/2018 base residual
auction, and we expect commercial operations to commence during the
second quarter of 2017. The project’s key permits and approvals are
being actively pursued and major equipment purchase commitments were
executed during the third quarter of 2014.

PJM Development Opportunities: We are currently evaluating
opportunities to develop additional projects in the PJM market area that
feature cost advantages such as existing infrastructure and favorable
transmission queue positions. These projects are continuing to advance
entitlements (such as permits, zoning and transmission) for their
potential future development.

All Segments:

Turbine Modernization: We continue to move forward with our
turbine modernization program. Through September 30, 2014, we have
completed the upgrade of thirteen Siemens and eight GE turbines totaling
approximately 210 MW and have committed to upgrade approximately three
additional turbines. Similarly, we have the opportunity at several of
our power plants in Texas to implement further turbine modernizations to
add as much as 500 MW of incremental capacity across the region at
attractive prices. In addition, we have begun a program to update our
dual-fueled turbines at certain of our power plants in our East segment.
Our decision to invest in these turbine modernizations depends upon,
among other things, further clarity on market design reforms currently
being considered.

___________

5 Represents incremental baseload capacity at annual average
conditions. Incremental summer peaking capacity is approximately 200 MW
per unit, supplemented by incremental efficiencies across the balance of
plant.

Customer-oriented Growth:— We entered into a new one-year PPA
with Guadalupe Valley Electric Cooperative to provide approximately
270 MW of power from our Texas power plant fleet commencing in June
2016— We entered into a new ten-year PPA with the Sonoma Clean
Power Authority to provide 15 MW of renewable power from our Geysers
assets commencing in January 2017. The capacity under contract will
vary by year, increasing up to a maximum of 50 MW for years 2024
through 2026— We entered into a new three-year resource adequacy
contract with Southern California Edison (SCE) for our Pastoria Energy
Facility commencing in January 2016. The capacity under contract will
initially be 238 MW and will increase to 476 MW during the final year
of the contract— We entered into a new two-year resource
adequacy contract with SCE for our Delta Energy Center for 500 MW of
capacity commencing in January 2017— We entered into a new PPA
with a term of up to 27 months with Duke Energy Florida, Inc., subject
to certain approvals, to provide 515 MW of power and capacity from our
Osprey Energy Center which commenced in October 2014.

___________

6 According to EEI Safety Survey (2013).

2014 & 2015 FINANCIAL OUTLOOK

(in millions, except per share amounts)

Full Year 2014

Full Year 2015

Adjusted EBITDA

$

1,915 - 1,965

$

1,900 - 2,100

Less:

Operating lease payments

35

35

Major maintenance expense and maintenance capital expenditures(1)

405

395

Cash interest, net(2)

650

630

Cash taxes

20

25

Other

5

5

Adjusted Free Cash Flow

$

800 - 850

$

810 - 1,010

Per Share Estimate (diluted)

$

1.90 - 2.05

$

2.10 - 2.60

Debt amortization(3)

$

(320

)

$

(210

)

Growth capital expenditures (net of debt funding)

$

(275

)

$

(355

)

________

(1) Includes projected major maintenance expense of $240 million
and $235 million and maintenance capital expenditures of $165 million
and $160 million in 2014 and 2015, respectively. Capital expenditures
exclude major construction and development projects.

(2) Includes commitment, letter of credit and other bank fees from
both consolidated and unconsolidated investments, net of capitalized
interest and interest income.

(3) Includes $120 million of 2023 First Lien Notes to be redeemed
in the fourth quarter of 2014.

As detailed above, today we are narrowing our 2014 guidance. We now
project Adjusted EBITDA of $1,915 million to $1,965 million, Adjusted
Free Cash Flow of $800 million to $850 million and Adjusted Free Cash
Flow Per Share of $1.90 to $2.05.

We are also initiating guidance for 2015. We expect Adjusted EBITDA of
$1,900 million to $2,100 million, Adjusted Free Cash Flow of $810
million to $1,010 million and Adjusted Free Cash Flow Per Share of $2.10
to $2.60. We also expect to invest $355 million in our ongoing
growth-related projects during the year, including the expected
completion of our Garrison Energy Center and the start of construction
of our York 2 Energy Center.

INVESTOR CONFERENCE CALL AND WEBCAST

We will host a conference call to discuss our financial and operating
results for the third quarter of 2014 on Thursday, November 6, 2014, at
10 a.m. Eastern time / 9 a.m. Central time. A listen-only webcast of the
call may be accessed through our website at www.calpine.com,
or by dialing (800) 447-0521 in the U.S. or (847) 413-3238 outside the
U.S. The confirmation code is 38036868. An archived recording of the
call will be made available for a limited time on our website or by
dialing (888) 843-7419 in the U.S. or (630) 652-3042 outside the U.S.
and providing confirmation code 38036868. Presentation materials to
accompany the conference call will be available on our website on
November 6, 2014.

ABOUT CALPINE

Calpine Corporation is America’s largest generator of electricity from
natural gas and geothermal resources. Our fleet of 87 power plants in
operation or under construction represents approximately 26,000
megawatts of generation capacity. Serving customers in 17 states and
Canada, we specialize in developing, constructing, owning and operating
natural gas-fired and renewable geothermal power plants that use
advanced technologies to generate power in a low-carbon and
environmentally responsible manner. Our clean, efficient, modern and
flexible fleet is uniquely positioned to benefit from the secular trends
affecting our industry, including the abundant and affordable supply of
clean natural gas, stricter environmental regulation, aging power
generation infrastructure and the increasing need for dispatchable power
plants to successfully integrate intermittent renewables into the grid.
We focus on competitive wholesale power markets and advocate for
market-driven solutions that result in nondiscriminatory forward price
signals for investors. Please visit www.calpine.com
to learn more about why Calpine is a generation ahead - today.

Calpine’s Quarterly Report on Form 10-Q for the quarter ended September
30, 2014, has been filed with the Securities and Exchange Commission
(SEC) and may be found on the SEC’s website at www.sec.gov.

FORWARD-LOOKING INFORMATION

In addition to historical information, this release contains
“forward-looking statements” within the meaning of the Private
Securities Litigation Reform Act of 1995, Section 27A of the Securities
Act, and Section 21E of the Exchange Act. Forward-looking statements may
appear throughout this release. We use words such as “believe,”
“intend,” “expect,” “anticipate,” “plan,” “may,” “will,” “should,”
“estimate,” “potential,” “project” and similar expressions to identify
forward-looking statements. Such statements include, among others, those
concerning our expected financial performance and strategic and
operational plans, as well as all assumptions, expectations,
predictions, intentions or beliefs about future events. You are
cautioned that any such forward-looking statements are not guarantees of
future performance and that a number of risks and uncertainties could
cause actual results to differ materially from those anticipated in the
forward-looking statements. Such risks and uncertainties include, but
are not limited to:

Financial results that may be volatile and may not reflect
historical trends due to, among other things, seasonality of demand,
fluctuations in prices for commodities such as natural gas and power,
changes in U.S. macroeconomic conditions, fluctuations in liquidity
and volatility in the energy commodities markets and our ability to
hedge risks;

Laws, regulations and market rules in the markets in which we
participate and our ability to effectively respond to changes in laws,
regulations or market rules or the interpretation thereof including
those related to the environment, derivative transactions and market
design in the regions in which we operate;

Our ability to manage our liquidity needs and to comply with
covenants under our First Lien Notes, Senior Unsecured Notes,
Corporate Revolving Facility, First Lien Term Loans, CCFC Term Loans
and other existing financing obligations;

Risks associated with the operation, construction and development
of power plants including unscheduled outages or delays and plant
efficiencies;

Risks related to our geothermal resources, including the adequacy
of our steam reserves, unusual or unexpected steam field well and
pipeline maintenance requirements, variables associated with the
injection of water to the steam reservoir and potential regulations or
other requirements related to seismicity concerns that may delay or
increase the cost of developing or operating geothermal resources;

The unknown future impact on our business from the Dodd-Frank Act
and the rules to be promulgated thereunder;

Competition, including risks associated with marketing and selling
power in the evolving energy markets;

Structural changes in the supply and demand of power, resulting
from the development of new fuels or technologies and demand-side
management tools;

The expiration or early termination of our PPAs and the related
results on revenues;

Future capacity revenues may not occur at expected levels;

Natural disasters, such as hurricanes, earthquakes and floods, acts
of terrorism or cyber attacks that may impact our power plants or the
markets our power plants serve and our corporate headquarters;

Disruptions in or limitations on the transportation of natural gas,
fuel oil and transmission of power;

Present and possible future claims, litigation and enforcement
actions; and

Other risks identified in this press release and in our 2013 Form
10-K.

Given the risks and uncertainties surrounding forward-looking
statements, you should not place undue reliance on these statements.
Many of these factors are beyond our ability to control or predict. Our
forward-looking statements speak only as of the date of this release.
Other than as required by law, we undertake no obligation to update or
revise forward-looking statements, whether as a result of new
information, future events, or otherwise.

Adjustments to reconcile net income to net cash provided by
operating activities:

Depreciation and amortization expense(1)

486

474

Debt extinguishment costs

35

28

Deferred income taxes

(9

)

18

Impairment losses

123

—

(Gain) on sale of assets, net

(753

)

—

Mark-to-market activity, net

(88

)

(14

)

(Income) from unconsolidated investments in power plants

(18

)

(25

)

Return on unconsolidated investments in power plants

13

23

Stock-based compensation expense

30

28

Other

—

3

Change in operating assets and liabilities:

Accounts receivable

(120

)

(219

)

Derivative instruments, net

(69

)

47

Other assets

54

(111

)

Accounts payable and accrued expenses

127

(11

)

Other liabilities

(54

)

63

Net cash provided by operating activities

504

415

Cash flows from investing activities:

Purchases of property, plant and equipment

(354

)

(472

)

Proceeds from sale of power plants, interests and other

1,573

—

Purchase of Guadalupe Energy Center, net of cash

(656

)

—

(Increase) decrease in restricted cash

(15

)

5

Other

2

(1

)

Net cash provided by (used in) investing activities

550

(468

)

Cash flows from financing activities:

Borrowings under CCFC Term Loans

420

1,197

Repayment of CCFC Term Loans, CCFC Notes and First Lien Term Loans

(34

)

(1,022

)

Borrowings under Senior Unsecured Notes

2,800

—

Repayments of First Lien Notes

(2,800

)

—

Borrowings from project financing, notes payable and other

79

139

Repayments of project financing, notes payable and other

(116

)

(51

)

Distribution to noncontrolling interest holder

(12

)

—

Financing costs

(55

)

(27

)

Stock repurchases

(767

)

(462

)

Proceeds from exercises of stock options

19

19

Net cash used in financing activities

(466

)

(207

)

Net increase (decrease) in cash and cash equivalents

588

(260

)

Cash and cash equivalents, beginning of period

941

1,284

Cash and cash equivalents, end of period

$

1,529

$

1,024

Cash paid during the period for:

Interest, net of amounts capitalized

$

534

$

547

Income taxes

$

19

$

22

Supplemental disclosure of non-cash investing activities:

Change in capital expenditures included in accounts payable

$

8

$

10

__________

(1) Includes depreciation and amortization included in fuel and
purchased energy expense and interest expense on our Consolidated
Condensed Statements of Operations.

REGULATION G RECONCILIATIONS

Net Income (Loss), As Adjusted, Commodity Margin, Adjusted EBITDA and
Adjusted Free Cash Flow are non-GAAP financial measures that we use as
measures of our performance. These measures should be viewed as a
supplement to and not a substitute for our U.S. GAAP measures of
performance.

Net Income (Loss), As Adjusted, represents net income
(loss) attributable to Calpine, adjusted for certain non-cash and
non-recurring items as previously detailed in Table 1, including
mark-to-market (gain) loss on derivatives, and other adjustments. Net
Income (Loss), As Adjusted, is presented because we believe it is a
useful tool for assessing the operating performance of our company in
the current period. Net Income (Loss), As Adjusted, is not intended to
represent net income (loss), the most comparable U.S. GAAP measure, as
an indicator of operating performance and is not necessarily comparable
to similarly titled measures reported by other companies.

Commodity Margin includes our power and steam revenues,
sales of purchased power and physical natural gas, capacity revenue,
revenue from renewable energy credits, sales of surplus emission
allowances, transmission revenue and expenses, fuel and purchased energy
expense, fuel transportation expense, environmental compliance expense,
and realized settlements from our marketing, hedging, optimization and
trading activities including natural gas transactions hedging future
power sales, but excludes mark-to-market activity and other revenues. We
believe that Commodity Margin is a useful tool for assessing the
performance of our core operations and is a key operational measure
reviewed by our chief operating decision maker. Commodity Margin does
not intend to represent income (loss) from operations, the most
comparable U.S. GAAP measure, as an indicator of operating performance
and is not necessarily comparable to similarly titled measures reported
by other companies.

Adjusted EBITDA represents net income (loss) attributable
to Calpine before net (income) loss attributable to the noncontrolling
interest, interest, taxes, depreciation and amortization, adjusted for
certain non-cash and non-recurring items as detailed in the following
reconciliation. Adjusted EBITDA is not intended to represent cash flows
from operations or net income (loss) as defined by U.S. GAAP as an
indicator of operating performance and is not necessarily comparable to
similarly titled measures reported by other companies.

We believe Adjusted EBITDA is useful to investors and other users of our
financial statements in evaluating our operating performance because it
provides them with an additional tool to compare business performance
across companies and across periods. We believe that EBITDA is widely
used by investors to measure a company’s operating performance without
regard to items such as interest expense, taxes, depreciation and
amortization, which can vary substantially from company to company
depending upon accounting methods and book value of assets, capital
structure and the method by which assets were acquired.

Additionally, we believe that investors commonly adjust EBITDA
information to eliminate the effects of restructuring and other
expenses, which vary widely from company to company and impair
comparability. As we define it, Adjusted EBITDA represents EBITDA
adjusted for the effects of impairment losses, gains or losses on sales,
dispositions or retirements of assets, any mark-to-market gains or
losses from accounting for derivatives, adjustments to exclude the
Adjusted EBITDA related to the noncontrolling interest, stock-based
compensation expense, operating lease expense, non-cash gains and losses
from foreign currency translations, major maintenance expense, gains or
losses on the repurchase or extinguishment of debt, non-cash
GAAP-related adjustments to levelize revenues from tolling agreements
and any extraordinary, unusual or non-recurring items plus adjustments
to reflect the Adjusted EBITDA from our unconsolidated investments. We
adjust for these items in our Adjusted EBITDA as our management believes
that these items would distort their ability to efficiently view and
assess our core operating trends.

In summary, our management uses Adjusted EBITDA as a measure of
operating performance to assist in comparing performance from period to
period on a consistent basis and to readily view operating trends, as a
measure for planning and forecasting overall expectations and for
evaluating actual results against such expectations, and in
communications with our Board of Directors, shareholders, creditors,
analysts and investors concerning our financial performance.

Adjusted Free Cash Flow represents net income before
interest, taxes, depreciation and amortization, as adjusted, less
operating lease payments, major maintenance expense and maintenance
capital expenditures, net cash interest, cash taxes and other
adjustments, including non-recurring items. Adjusted Free Cash Flow is
presented because we believe it is a useful tool for assessing the
financial performance of our company in the current period. Adjusted
Free Cash Flow is a performance measure and is not intended to represent
net income (loss), the most directly comparable U.S. GAAP measure, or
liquidity and is not necessarily comparable to similarly titled measures
reported by other companies.

Commodity Margin Reconciliation

During the third quarter of 2014, we altered the composition of our
geographic segments to combine our former North and Southeast segments
into one segment which was renamed the East segment. This change
reflects the manner in which our geographic information is presented
internally to our chief operating decision maker following the sale of
six power plants in July 2014 from what was formerly our Southeast
segment. Thus, beginning in the third quarter of 2014, our reportable
segments are West (including geothermal), Texas and East (including
North, Southeast and Canada).

During the fourth quarter of 2013, we changed the methodology previously
used during 2013 for allocating corporate expenses to our segments. This
change had no impact to our Consolidated Condensed Statements of
Operations for the three and nine months ended September 30, 2013;
however, segment amounts previously reported for the three and nine
months ended September 30, 2013, were adjusted by immaterial amounts.

The following tables reconcile our Commodity Margin to its U.S. GAAP
results for the three months ended September 30, 2014 and 2013 (in
millions):

Three Months Ended September 30, 2014

Consolidation

And

West

Texas

East

Elimination

Total

Commodity Margin(1)

$

361

$

346

$

237

$

—

$

944

Add: Mark-to-market commodity activity, net and other(2)

41

(64

)

4

(6

)

(25

)

Less:

Plant operating expense

91

77

55

(8

)

215

Depreciation and amortization expense

65

51

38

(1

)

153

Sales, general and other administrative expense

11

18

8

—

37

Other operating expenses

12

1

6

4

23

Impairment losses

—

—

123

—

123

(Gain) on sale of assets, net

—

—

(753

)

—

(753

)

(Income) from unconsolidated investments in power plants

—

—

(5

)

—

(5

)

Income from operations

$

223

$

135

$

769

$

(1

)

$

1,126

Three Months Ended September 30, 2013

Consolidation

And

West

Texas

East

Elimination

Total

Commodity Margin(1)

$

337

$

328

$

320

$

—

$

985

Add: Mark-to-market commodity activity, net and other(2)

16

(5

)

3

(8

)

6

Less:

Plant operating expense

84

56

67

(7

)

200

Depreciation and amortization expense

58

41

51

—

150

Sales, general and other administrative expense

9

13

10

1

33

Other operating expenses

12

2

9

(3

)

20

(Income) from unconsolidated investments in power plants

—

—

(9

)

—

(9

)

Income from operations

$

190

$

211

$

195

$

1

$

597

The following tables reconcile our Commodity Margin to its U.S. GAAP
results for the nine months ended September 30, 2014 and 2013 (in
millions):

Nine Months Ended September 30, 2014

Consolidation

And

West

Texas

East

Elimination

Total

Commodity Margin(3)

$

791

$

644

$

786

$

—

$

2,221

Add: Mark-to-market commodity activity, net and other(4)

91

74

(31

)

(23

)

111

Less:

Plant operating expense

291

250

237

(24

)

754

Depreciation and amortization expense

183

141

129

—

453

Sales, general and other administrative expense

28

48

32

—

108

Other operating expenses

39

4

22

1

66

Impairment losses

—

—

123

—

123

(Gain) on sale of assets, net

—

—

(753

)

—

(753

)

(Income) from unconsolidated investments in power plants

—

—

(18

)

—

(18

)

Income from operations

$

341

$

275

$

983

$

—

$

1,599

Nine Months Ended September 30, 2013

Consolidation

And

West

Texas

East

Elimination

Total

Commodity Margin(3)

$

737

$

537

$

705

$

—

$

1,979

Add: Mark-to-market commodity activity, net and other(4)

(2

)

18

12

(24

)

4

Less:

Plant operating expense

271

214

221

(22

)

684

Depreciation and amortization expense

164

125

153

(1

)

441

Sales, general and other administrative expense

24

43

34

1

102

Other operating expenses

33

4

25

(4

)

58

(Income) from unconsolidated investments in power plants

—

—

(25

)

—

(25

)

Income from operations

$

243

$

169

$

309

$

2

$

723

_________

(1) Commodity Margin related to the six power plants sold in our
East segment on July 3, 2014, was not significant for the three months
ended September 30, 2014. Commodity Margin related to these plants was
$65 million for the three months ended September 30, 2013.

(2) Includes $49 million and $44 million of lease levelization and
$4 million and $4 million of amortization expense for the three months
ended September 30, 2014 and 2013, respectively.

(3) Our East segment includes Commodity Margin of $81 million and
$122 million for the nine months ended September 30, 2014 and 2013,
respectively, related to the six power plants in our East segment that
were sold in July 2014.

(4) Includes $(7) million and $17 million of lease levelization and
$11 million and $11 million of amortization expense for the nine months
ended September 30, 2014 and 2013, respectively.

Consolidated Adjusted EBITDA Reconciliation

In the following table, we have reconciled our Adjusted EBITDA and
Adjusted Free Cash Flow to our net income attributable to Calpine for
the three and nine months ended September 30, 2014 and 2013, as reported
under U.S. GAAP.

Adjustments to reflect Adjusted EBITDA from unconsolidated
investments and exclude the noncontrolling interest(4)

(3

)

—

6

13

Stock-based compensation expense

8

8

30

28

Loss on dispositions of assets

—

1

1

5

Acquired contract amortization

4

4

11

11

Other

54

44

2

17

Total Adjusted EBITDA

$

745

$

802

$

1,604

$

1,431

Less:

Operating lease payments

9

9

26

26

Major maintenance expense and capital expenditures(5)

67

62

326

303

Cash interest, net(6)

160

173

497

528

Cash taxes

2

1

16

18

Other

1

1

4

5

Adjusted Free Cash Flow(7)

$

506

$

556

$

735

$

551

Weighted average shares of common stock outstanding (diluted, in
thousands)

402,962

438,493

416,056

448,546

Adjusted Free Cash Flow Per Share (diluted)

$

1.26

$

1.27

$

1.77

$

1.23

_________

(1) Adjusted EBITDA related to the six power plants sold in our
East segment on July 3, 2014, was not significant for the three months
ended September 30, 2014. Adjusted EBITDA related to these plants was
$54 million for the three months ended September 30, 2013.

(2) Our East segment includes Adjusted EBITDA of $43 million and
$75 million for the nine months ended September 30, 2014 and 2013,
respectively, related to the six power plants in our East segment that
were sold in July 2014.

(3) Depreciation and amortization expense in the income from
operations calculation on our Consolidated Condensed Statements of
Operations excludes amortization of other assets.

(4) Adjustments to reflect Adjusted EBITDA from unconsolidated
investments include (gain) loss on mark-to-market activity of nil for
each of the three and nine months ended September 30, 2014 and 2013.

(5) Includes $39 million and $195 million in major maintenance
expense for the three and nine months ended September 30, 2014,
respectively, and $28 million and $131 million in maintenance capital
expenditure for the three and nine months ended September 30, 2014,
respectively. Includes $34 million and $185 million in major maintenance
expense for the three and nine months ended September 30, 2013,
respectively, and $28 million and $118 million in maintenance capital
expenditure for the three and nine months ended September 30, 2013,
respectively.

(6) Includes commitment, letter of credit and other bank fees from
both consolidated and unconsolidated investments, net of capitalized
interest and interest income.

(7) Excludes a decrease in working capital of $24 million and an
increase of $18 million for the three and nine months ended September
30, 2014, respectively, and an increase in working capital of $59
million and $265 million for the three and nine months ended September
30, 2013, respectively. Adjusted Free Cash Flow, as reported, excludes
changes in working capital, such that it is calculated on the same basis
as our guidance.

In the following table, we have reconciled our Adjusted EBITDA to our
Commodity Margin, both of which are non-GAAP measures, for the three and
nine months ended September 30, 2014 and 2013. Reconciliations for both
Adjusted EBITDA and Commodity Margin to comparable U.S. GAAP measures
are provided above. Amounts below are shown exclusive of the
noncontrolling interest.

Three Months Ended September 30,

Nine Months Ended September 30,

2014

2013

2014

2013

(in millions)

(in millions)

Commodity Margin

$

944

$

985

$

2,221

$

1,979

Other revenue

3

3

10

9

Plant operating expense(1)

(171

)

(160

)

(539

)

(480

)

Sales, general and administrative expense(2)

(33

)

(28

)

(93

)

(87

)

Other operating expenses(3)

(12

)

(11

)

(36

)

(32

)

Adjusted EBITDA from unconsolidated investments in power plants

13

15

41

44

Other

1

(2

)

—

(2

)

Adjusted EBITDA

$

745

$

802

$

1,604

$

1,431

_________

(1) Shown net of major maintenance expense, stock-based
compensation expense, non-cash loss on dispositions of assets and other
costs.

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